1. Field of the Invention
Embodiments disclosed herein relate generally to rotary drill bits used to drill well bores through the earth. More particularly, embodiments disclosed herein relate to steel-bodied drag bits.
2. Background Art
Rotary drill bits with no moving elements are typically referred to as “drag” bits. Drag bits are often used to drill a variety of rock formations. Drag bits include those having cutters (sometimes referred to as cutter elements, cutting elements or inserts) attached to the bit body. For example, the cutters may be formed having a substrate or support stud made of carbide, for example tungsten carbide, and an ultra hard cutting surface layer or “table” made of a polycrystalline diamond material or a polycrystalline boron nitride material deposited onto or otherwise bonded to the substrate at an interface surface.
An example of a prior art drag bit having a plurality of cutters with ultra hard working surfaces is shown in FIG. 1. The drill bit 10 includes a bit body 12 and a plurality of blades 14 that are formed on the bit body 12. The blades 14 are separated by channels or gaps 16 that enable drilling fluid to flow between and both clean and cool the blades 14 and cutters 18. Cutters 18 are held in the blades 14 at predetermined angular orientations and radial locations to present working surfaces 20 with a desired back rake angle against a formation to be drilled. Typically, the working surfaces 20 are generally perpendicular to the axis 19 and side surface 21 of a cylindrical cutter 18. Thus, the working surface 20 and the side surface 21 meet or intersect to form a circumferential cutting edge 22.
Orifices are typically formed in the drill bit body 12 and positioned in the gaps 16. The orifices are commonly adapted to accept nozzles 23. The orifices allow drilling fluid to be discharged through the bit in selected directions and at selected rates of flow between the cutting blades 14 for lubricating and cooling the drill bit 10, the blades 14 and the cutters 18. The drilling fluid also cleans and removes the cuttings as the drill bit rotates and penetrates the geological formation. The gaps 16, which may be referred to as “fluid courses,” are positioned to provide additional flow channels for drilling fluid and to provide a passage for formation cuttings to travel past the drill bit 10 toward the surface of a wellbore (not shown).
The drill bit 10 includes a shank 24 and a crown 26. Shank 24 is typically formed of steel or a matrix material and includes a threaded pin 28 for attachment to a drill string. Crown 26 has a cutting face 30 and outer side surface 32. The particular materials used to form drill bit bodies are selected to provide adequate strength and toughness, while providing good resistance to abrasive and erosive wear.
The combined plurality of surfaces 20 of the cutters 18 effectively forms the cutting face of the drill bit 10. Once the crown 26 is formed, the cutters 18 are positioned in the cutter pockets 34 and affixed by any suitable method, such as brazing, adhesive, mechanical means such as interference fit, or the like. The design depicted provides the cutter pockets 34 inclined with respect to the surface of the crown 26. The cutter pockets 34 are inclined such that cutters 18 are oriented with the working face 20 at a desired rake angle in the direction of rotation of the bit 10, so as to enhance cutting. It will be understood that in an alternative construction (not shown), the cutters can each be substantially perpendicular to the surface of the crown, while an ultra hard surface is affixed to a substrate at an angle on a cutter body or a stud so that a desired rake angle is achieved at the working surface.
A typical cutter 18 is shown in FIG. 2. The typical cutter 18 has a cylindrical cemented carbide substrate body 38 having an end face or upper surface 54, which may also be referred to as the “interface surface.” An ultra hard material layer (cutting layer) 44, such as polycrystalline diamond or polycrystalline cubic boron nitride layer, forms the working surface 20 and the cutting edge 22. A bottom surface 52 of the cutting layer 44 is bonded on to the upper surface 54 of the substrate 38. The joining surfaces 52 and 54 are herein referred to as the interface 46. The top exposed surface or working surface 20 of the cutting layer 44 is opposite the bottom surface 52. The cutting layer 44 typically has a flat or planar working surface 20, but may also have a curved exposed surface, that meets the side surface 21 at a cutting edge 22.
Bit bodies for drag bits may be selected from a matrix bit body and a steel bit body. Matrix bit bodies have good erosion and abrasion resistance, but the matrix material is relatively brittle which makes the matrix body susceptible to cracking and failure due to impact forces generated during drilling. While steel-bodied bits may have strength and toughness properties which make them resistant to cracking and failure due to impact forces generated during drilling, steel is more susceptible to erosive wear caused by high-velocity drilling fluids and formation fluids which carry abrasive particles, such as sand, rock cuttings, and the like. Thus, steel-bodied drag bits are generally coated with one or more “hard metals” such as metal oxides, metal nitrides, metal borides, metal carbides and alloys thereof to improve their erosion resistance. This erosion-resistant coating is commonly referred to as hardfacing.
The hard metal particles in the hardfacing are bonded to the steel bit body by a metal alloy (“binder alloy”), which is typically a nickel alloy. In effect, the hard metal particles are suspended in a matrix of nickel alloy forming a layer on the surface of the steel bit body. The hard metal particles give the hardfacing material hardness and wear resistance, while the matrix metal bonds the hard metal particles in place and provides some fracture toughness to the hardfacing.
A common mode of failure of steel-bodied bits is loss of cutters as the steel bit body is eroded away around the cutter. In order to solve this problem, hardfacing materials have been applied in the area surrounding the cutter pocket. However, erosion of the steel body around the cutters nonetheless may occur even when erosion-resistant hardfacing is applied in the area. The relatively thin coating of the hardfacing may crack, peel off or wear, exposing the softer steel body which is then rapidly eroded. Due to the high failure rates caused by the erosion undercutting of the steel body and poor coverage of hardfacing near and between the cutter pockets, a typical steel body bit generally achieves only one to two runs per bit.
Another method of preventing erosion of the steel around the cutters that can be used separately or in conjunction with a hardfacing involves the orientation of the orifices so that they spray drilling fluid directly at the earth formation rather than at the blades and/or cutters. The orifices may also be oriented so that they spray drilling fluid indirectly at the blades and/or cutters. However, this method of preventing erosion of the steel around the cutters is not satisfactory in many drilling applications due to the need to orient the spray of the drilling fluid more directly at the blade and cutters to prevent overheating of the cutters and other problematic phenomena such as bit balling.
Accordingly, there exists a need for a steel-bodied drag bit with greater bit body durability in the area surrounding the cutters, including greater erosion and abrasion resistance.